► In-situ upgrading of oil using hydrogen donors is a new process. In particular, very little research has been conducted with respect to in-situ oil upgrading…
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▼ In-situ upgrading of oil using hydrogen donors is a new process. In particular, very
little research has been conducted with respect to in-situ oil upgrading using hydrogen
donor under in-situ combustion. Several papers describe the use of metal additives
mixed with oil and their influence on oil properties such as viscosity and API gravity.
The main objective of my research is to determine if a catalyst mixed with a hydrogen
donor (tetralin) is going to affect the Jobo crude oil properties while undergoing in-situ
combustion.
Six runs were performed with Jobo crude oil (9-11?API) from the Orinoco Belt in
Venezuela. Four of the runs were successful. Two of them are base runs; the remaining
ones are with tetralin with concentration of 5 wt% (of oil) and catalyst with concentration
of 750 ppm. For all runs, the following were kept constant: the air injection rate (3 std.
L/min) and production (combustion tube outlet) pressure, 300 psig. Concentration by
weight of oil, water, and sand in the samples were approximately 4.8%, 4.2%, and 91%
respectively.
Oil viscosity at the end of combustion at 40 °C decreased from 42.3 and 73.6 to 16.6
and 25.2; API gravity at the end of combustion increased from 18.4 and 16.8 to 20 and
18.8. Oil recovery is higher; combustion front velocity is faster in the case of additives,
water production decreased. Since oil viscosity decreased and API gravity increased oil
moves faster and consequently combustion time is lower.
Advisors/Committee Members: Mamora, Daulat (advisor), Ikelle, Luc (committee member), Schubert, Jerome (committee member).

► Multiphase pumping with twin-screw pumps is a relatively new technology that has been proven successful in a variety of field applications. By using these pumps…
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▼ Multiphase pumping with twin-screw pumps is a relatively new technology that has been proven successful in a variety of field applications. By using these pumps to add energy to the combined gas and liquid wellstream with minimal separation, operators have been able to reduce capital costs while increasing overall production. In many cases, such as subsea operations, multiphase pumping is the only viable option to make remote wells economic. Despite their many advantages, some problems have been encountered when operating under conditions with high gas volume fractions (GVF). Twin-screw multiphase pumps experience a severe decrease in efficiency when operating under wet-gas conditions, GVF over 95%. Field operations have revealed severe vibration and thermal issues which can lead to damage of the pump internals, requiring expensive maintenance. The research presented in this thesis seeks to investigate two novel methods of improving the performance of twin-screw pumps under wet-gas conditions. The first involves increasing the viscosity of the liquid stream. We propose that by increasing the viscosity of the liquid phase, the pump throughput can be increased. Tests were conducted at high GVF using guar gel to increase the viscosity of the liquid phase. Along with results from a multiphase pump model the pump behavior under wet-gas conditions with increased liquid viscosity was evaluated. The experimental results indicate that at high GVF, viscosity is not a dominant parameter for determining pump performance. Possible reasons for this behavior were proposed. These results were not predicted by current pump models. Therefore, several suggestions for improving the model?s predictive performance were suggested. The second method is the direct injection of liquid into the pump casing. By selectively injecting liquid into specific pump chambers, it is believed that many of the vibration issues can be eliminated with the added benefit of additional pressure boosting capacity. Since this method requires extensive mechanical modifications to an existing pump, it was studied only analytically. Calculations were carried out that show that through-casing liquid injection is feasible. More favorable pressure profiles and increased boosting ability were demonstrated.
Advisors/Committee Members: Scott, Stuart (advisor), Glover, Charles (committee member), Mamora, Daulat (committee member).

► The three key steps of modern seismic imaging are (1) multiple attenuation, (2) velocity estimation, and (3) migration. The multiple-attenuation step is essentially designed to…
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▼ The three key steps of modern seismic imaging are (1) multiple attenuation, (2) velocity estimation, and (3) migration. The multiple-attenuation step is essentially designed to remove the energy that has bounces at the free surface (also known as "multiples"), since velocity estimation and migration assume that data contain only primaries (i.e., seismic events that have reflected or diffracted only once in the subsurface and have no free-surface reflection). The second step consists of estimating the velocity model such that the migration step can be solved as a linear inverse problem. This thesis concerns the multiple attenuation of towed-streamer data. We have proposed a new method for attenuating multiples and discussed how this method affects velocity estimation and migration.
The multiple-attenuation approach used today in the E&P industry is based on the scattering theory. It is carried out in two steps: (1) the prediction of multiples using data only, and (2) the subtraction of multiples contained in the data using predicted multiples. One of the interesting features of these multiple-attenuation methods is that they do not require any knowledge of the subsurface. However there are still two drawbacks that limit the usage of these methods. They are (1) the requirement of acquiring very large 3D datasets which are beyond the capability of current seismic acquisition technology, and (2) the requirement of acquiring near-offset (including zero-offset) data. The method developed in this thesis can potentially overcome these two problems. The novelty of our approach here is to image receiver ghosts of primaries – events which have one bounce in the subsurface and one bounce at the free-surface that is also the last bounce – instead of primaries themselves. We propose to predict two wavefields instead of a single wavefield, as is presently done. One wavefield contains all free-surface reflections, including receiver ghosts of primaries, ghosts of multiples, and multiples. The other wavefield does not contain receiver ghosts of primaries. We pose the problem of reconstructing receiver ghosts of primaries as solving a system of two equations with three unknowns. The two wavefields are used to construct the two equations. The three unknowns are (1) the receiver ghosts of primaries, (2) the multiples contained in the wavefield containing the receiver ghosts of primaries, and (3) the multiples contained in the other wavefield. We solve this underdetermined system by taking advantage of the fact that seismic data are sparse.
We have validated our approach using data generated by finite-difference modeling (FDM), which is by far the most accurate modeling tool for seismic data. Starting with a simple 1D model, we verified the effectiveness of predicting data containing multiples and receiver ghosts of primaries. Then we used the sparsity of seismic data to turn the system of two equations with three unknowns into a system of two equations with two unknowns on a datapoint basis. We have also validated our method for complex…
Advisors/Committee Members: Ikelle, Luc (advisor), Sun, Yuefeng (committee member), Mamora, Daulat (committee member).

▼ This study presents the results of nano-particle and surfactant-stabilized solvent-based emulsion core flooding studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion. Specifically, nano-emulsion systems with high viscosity have been injected into sandstone cores containing Alaska North Slope West Sak heavy oil with 16 API, which was dewatered in the laboratory condition.
The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR (enhanced oil recovery) process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems.
Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nano-emulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation.
In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat.
In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.
Advisors/Committee Members: Mamora, Daulat (advisor), Zhu, Ding (committee member), Cheng, zhengdong (committee member).

► Seismic modeling is a technique for simulating wave propagation through the subsurface. For a given geological model, seismic modeling allows us to generate snapshots of…
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▼ Seismic modeling is a technique for simulating wave propagation through the
subsurface. For a given geological model, seismic modeling allows us to generate
snapshots of wave propagation and synthetic data. In my dissertation, for real seismic
events I have chosen to implement the finite-difference modeling technique. When
adequate discretization in space and time is possible, the finite-difference technique is
by far one of the most accurate tools for simulating elastic-wave propagation through
complex geological models.
In recent years, a significant amount of work has been done in our group using
2D finite-difference modeling. For complex salt structures which exploration and pro-
duction industries meet today, 2D finite-difference modeling is not sufficient to study
subsalt imaging or the demultiple of subsalt models. That is why I have developed a
3D finite-difference modeling code.
One of the key challenges that I have met in developing the 3D finite-difference
code is to adapt the absorbing boundary conditions. Absorbing boundary conditions
are needed to describe the infinite geological models by limited computing domain.
I have validated the 3D finite-difference code by comparing its results with analytic
solutions. I have used 3D finite-difference program to generate data corresponding
to 3D complex model which describes salt and subsalt structures of Gulf of Mexico.
The resulting data include reflections, diffractions and other scattering phenomena.
I have also used finite-difference program in anisotropic context to show that we can effectively predict shear-wave splitting and triplication in the data.
There are new sets of events that are not directly recorded in seismic data, they
have been called virtual events. These events are turning to be as important as real
events in modern data processing. Therefore we also have to learn how to model them.
Unfortunately, they cannot yet be modeled directly from finite-difference. Here I will
describe how to model these events by using cross correlation type representation
theorem. As illustration of how important of virtual events for seismic data process-
ing, I also described an internal multiple attenuation technique which utilized virtual
events.
Advisors/Committee Members: Ikelle, Luc (advisor), Mamora, Daulat (committee member), Sun, Yuefeng (committee member), Zhan, Hongbin (committee member).

▼ Uncertainty quantification involves sampling the reservoir parameters correctly from a
posterior probability function that is conditioned to both static and dynamic data.
Rigorous sampling methods like Markov Chain Monte Carlo (MCMC) are known to
sample from the distribution but can be computationally prohibitive for high resolution
reservoir models. Approximate sampling methods are more efficient but less rigorous for
nonlinear inverse problems. There is a need for an efficient and rigorous approach to
uncertainty quantification for the nonlinear inverse problems.
First, we propose a two-stage MCMC approach using sensitivities for quantifying
uncertainty in history matching geological models. In the first stage, we compute the
acceptance probability for a proposed change in reservoir parameters based on a
linearized approximation to flow simulation in a small neighborhood of the previously
computed dynamic data. In the second stage, those proposals that passed a selected
criterion of the first stage are assessed by running full flow simulations to assure the
rigorousness.
Second, we propose a two-stage MCMC approach using response surface models for
quantifying uncertainty. The formulation allows us to history match three-phase flow
simultaneously. The built response exists independently of expensive flow simulation,
and provides efficient samples for the reservoir simulation and MCMC in the second
stage. Third, we propose a two-stage MCMC approach using upscaling and non-parametric
regressions for quantifying uncertainty. A coarse grid model acts as a surrogate for the
fine grid model by flow-based upscaling. The response correction of the coarse-scale
model is performed by error modeling via the non-parametric regression to approximate
the response of the computationally expensive fine-scale model.
Our proposed two-stage sampling approaches are computationally efficient and
rigorous with a significantly higher acceptance rate compared to traditional MCMC
algorithms.
Finally, we developed a coarsening algorithm to determine an optimal reservoir
simulation grid by grouping fine scale layers in such a way that the heterogeneity
measure of a defined static property is minimized within the layers. The optimal number
of layers is then selected based on a statistical analysis.
The power and utility of our approaches have been demonstrated using both
synthetic and field examples.
Advisors/Committee Members: Datta-Gupta, Akhil (advisor), Efendiev, Yalchin (advisor), Jafarpour, Behnam (committee member), Mamora, Daulat (committee member).

► Reservoir geomechanics is a production induced phenomena that is experienced in large number of fields around the world. Hydrocarbon production changes the pore pressure which…
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▼ Reservoir geomechanics is a production induced phenomena that is experienced
in large number of fields around the world. Hydrocarbon production changes the pore
pressure which in turn alters the in-situ stress state. For reservoirs that are either stress
sensitive or where rock is soft and unconsolidated, stresses have appreciable effect on
rock properties like porosity and permeability. Anisotropic and isotropic permeability
changes affect flow direction and movement of flood front thereby influencing well
performance and reservoir productivity. Coupling of geomechanical calculation with
multi-phase flow calculation is needed to make prudent predictions about the reservoir
production and recovery. The post processing tools provided with the simulators cannot
monitor flood front movement and fail to capture important information like flow
directionality and dominant phase in a flow. Geomechanical simulation is combined with
streamline tracing to aid in better understanding of the reservoir dynamics through
visualization of flow patterns in the reservoir. Streamline tracing is a proved reservoir
engineering tool that is widely used by industry experts to capture information on flood
movement, injector-producer relations and swept area. In the present research, we have incorporated total velocity streamlines and phase
streamlines for coupled geomechanical simulation and compared the results with
streamline tracing for conventional reservoir simulator to explain geomechanics behavior
on reservoir flow processes in a more detailed and appealing manner. Industry standard
simulators are used for coupled geomechanical simulation and conventional simulation
and streamline tracing has been done through in-house tracing code.
The research demonstrates the benefits and power of streamline tracing in
visualizing flow patterns through work on two cases; first, a synthetic case for studying
water injection in a five spot pattern and second, a SPE 9th comparative study. The
research gives encouraging results by showing how geomechanics influences reservoir
flow paths and reservoir dynamics through visualization of flow. The streamlines
captures flow directionality, information regarding appearance and disappearance of gas
phase and the connectivity between injector and producer.
Advisors/Committee Members: Datta-Gupta, Akhil (advisor), Efendiev, Yalchin (committee member), Mamora, Daulat D. (committee member).

▼ Numerous isolated carbonate platforms developed in the Central Luconia
Province of offshore Sarawak (during Middle to Late Miocene time). Fault-bounded
highs produced largely by extensional deformation and later overprinted by strike-slip
deformation provided substrates for the platforms and affected their growth histories.
Flooding of these structural highs at ~16.5 Ma initiated carbonate sedimentation nearly
simultaneously across the area. Later, third-order sea-level fluctuations and extrinsic
factors such as differential subsidence, paleowind patterns and siliciclastic influx then
controlled the internal architecture of the platforms. 2-D regional seismic lines, publicdomain
data and published literature were used to analyze growth patterns and demise of
carbonate platforms across the study area.
Five Growth Stages were recognized in the carbonate platforms based on seismic
facies analysis and stratigraphic relationships between reflectors. Platforms from the
southeastern part of Central Luconia are thicker and larger than platforms located toward
the central and northwestern areas, which reflect greater long-term tectonic subsidence
to the southeast. Additionally, northwestward prograding siliciclastic sediments from mainland Borneo caused additional flexural subsidence in the eastern part of the area and
environmental deterioration for platforms located beyond the range of active siliciclastic
sedimentation. Both of these factors reduced the growth potential of platforms and thus
subdued carbonate development.
Platform termination was regionally diachronous and was produced in two steps.
The first platforms drowned (~12.5-9.7 Ma) were in the eastern parts of the study area
which were affected by incoming siliciclastic sediments and high local subsidence.
Platforms drowned later (~6.3-5.5 Ma) were caused by a rapid sea-level rise combined
with an intense local subsidence. Carbonate accumulation rates were measured between
intraplatform markers, resulting in a trend that indicates a decrease in sedimentation rate
with the square root of time.
Comparisons between Central Luconia carbonates and age-equivalent carbonate
platforms elsewhere in East Natuna Basin showed that Central Luconia carbonate
platforms were drowned earlier (latest late Miocene time) than East Natuna carbonate
platforms (Early Pliocene time).
Advisors/Committee Members: Dorobek, Steven L. (advisor), Mamora, Daulat (committee member), Willis, Brian J. (committee member).

► Isolated carbonate platforms and buildups of the Likas Formation provide a long record of carbonate sedimentation in the southern end of the Southwest Palawan Basin.…
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▼ Isolated carbonate platforms and buildups of the Likas Formation provide a long
record of carbonate sedimentation in the southern end of the Southwest Palawan Basin.
While most carbonate platforms terminated in early Miocene and middle Miocene time
in northern parts of western offshore Palawan (i.e. Northwest Palawan Basin and central
South Palawan), carbonate deposition began later in the south during late middle
Miocene time.
Carbonate platforms of the Likas Formation developed in the Paragua sub-basin,
which is interpreted to be a depozone eastward of the Palawan accretionary wedge in the
structurally complex Southwest Palawan Basin. A regional 2D seismic grid and borehole
data from four wells were used to analyze the growth patterns of the carbonate
platforms, identify seismic facies, and reconstruct the evolution of the platforms.
The carbonate platforms developed on the folded and faulted middle to premiddle
Miocene siliciclastic strata. These older siliciclastic units were thrusted onto the
southern end of the North Palawan microcontinental fragment, which represents a block
of continental crust that drifted southward from South China during early Tertiary time.
The platforms aggraded over time and backstepped to keep pace with increasing rates of
relative sea level rise. Karst features are recognizable on seismic sections and indicate that the platforms were subaerially exposed at various times during their development.
The platforms exhibit variable morphology from faulting and tilting. The platforms
terminated in early Pliocene time, as relative sea level continued to rise, and were buried
by deep-marine siliciclastic units.
Advisors/Committee Members: Dorobek, Steven L. (advisor), Mamora, Daulat (committee member), Willis, Brian J. (committee member).

► Experimental and analytical studies have been carried out to better understand the effects of additives on viscosity, density and surface tension of intermediate and heavy…
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▼ Experimental and analytical studies have been carried out to better understand the effects of additives on viscosity, density and surface tension of intermediate and heavy crude oils. The studies have been conducted for the following oil samples: San Francisco oil from Columbia with specific gravity of 28o-29o API, Duri oil with gravity of 19o-21o API, Jobo oil with gravity of 8o-9o API and San Ardo oil gravity of 11o-13o API. The additive used in all of the experiments is petroleum distillate. The experiments consist of using petroleum distillate as an additive for different samples of heavy crude oils. The experiments include making a mixture by adding petroleum distillate to oil samples and measuring surface tension, viscosity and density of pure oil samples and mixtures at different temperatures. The petroleum distillate/oil ratios are the following ratios: 1:100, 2:100, 3:100, 4:100 and 5:100.
Experimental results showed that use of petroleum distillate as an additive increases API gravity and leads to reduction in viscosity and surface tension for all the samples. Results showed for all petroleum distillate/oil ratios viscosity and interfacial tension decreases with temperature. As petroleum distillate/oil ratio increases, oil viscosity and surface tension decrease more significantly at lower temperatures than at higher temperatures. After all experiments were completed an analytical correlation was done based on the experiment results to develop ?mixing rules?. Using this correlation viscosity, density and surface tension of different petroleum distillate/oil mixtures were obtained (output).These had properties of pure oil and petroleum distillate, mixture ratios and temperatures at which measurement is supposed to be done (output). Using this correlation a good match was achieved. For all of the cases (viscosity, density and surface tension), correlation coefficient (R?) was more than 0.9 which proved to be optimum for a really good match.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Ikelle, Luc T. (committee member), Schubert, Jerome J. (committee member).

► Using a hydrogen donor and a catalyst for upgrading and increasing oil recovery during in situ combustion is a known and proven technique. Based on…
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▼ Using a hydrogen donor and a catalyst for upgrading and increasing oil recovery during in situ combustion is a known and proven technique. Based on research conducted on this process, it is clear that widespread practice in industry is the usage of tetralin as a hydrogen donor. The objective of the study is to find a cheaper hydrogen donor with better or the same upgrading performance. Decalin (C10H18) is used in this research as a hydrogen donor. The experiments have been carried out using field oil and water saturations, field porosity and crushed core for porous medium.
Four in situ combustion runs were performed with Gulf of Mexico heavy oil, and three of them were successful. The first run was a control run without any additives to create a base for comparison. The next two runs were made with premixed decalin (5 percent by oil weight) and organometallic catalyst (750 ppm). The following conditions were kept constant during all experimental runs: air injection rate at 3.1 L/min and combustion tube outlet pressure at 300 psig. Analysis of the performance of decalin as a hydrogen donor in in-situ combustion included comparison of results with an experiment where tetralin was used. Data from experiments of Palmer (Palmer-Ikuku, 2009) was used for this purpose, where the same oil, catalyst and conditions were used.
Results of experiments using decalin showed better quality of produced oil, higher recovery factor, faster combustion front movement and higher temperatures of oxidation. API gravity of oil in a run with decalin is higher by 4 points compared to a base run and increased 5 points compared to original oil. Oil production increased by 7 percent of OOIP in comparison with base run and was 2 percent higher than the experiment with tetralin. The time required for the combustion front to reach bottom flange decreased 1.6 times compared to the base run. The experiments showed that decalin and organometallic catalysts perform successfully in in situ combustion, and decalin is a worthy replacement for tetralin.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Schubert, Jerome J. (committee member), Sun, Yuefeng (committee member).

► Many attempts have been made to control water conformance. It is very costly to produce, treat and dispose of water, and produced water represents the…
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▼ Many attempts have been made to control water conformance. It is very costly to
produce, treat and dispose of water, and produced water represents the largest waste
stream associated with oil and gas production. The production of large amounts of water
results in: (a) the need for more complex water?oil separation; (b) corrosion of wellbore
and other equipment; (c) a rapid decline in hydrocarbon production rate and ultimate
recovery; and (d) consequently, premature abandonment of a well or field, leaving
considerable hydrocarbons unproduced.
Sometimes water production results from heterogeneities in the horizontal
direction, which leads to uneven movement of the flood front and subsequent early
breakthrough of water from high permeability layers. This problem is exacerbated if
there is (vertical) hydraulic communication between layers so that crossflow can occur.
One of the novel technologies in chemical enhanced oil recovery (EOR) is a gel
type called deep diverting gel (DDG), which describes material that functions by
plugging thief zones deep from the well where they were being injected. To evaluate the performance of this new treatment method, we will (1) model the treatment methods, (2)
conduct economic analysis, and (3) compare different EOR methods.
We have conducted relevant literature review about the development, design,
modeling and economics of the enhanced oil recovery methods. Schlumberger's Eclipse
simulator software has been used for modeling purposes.
Modeling runs have demonstrated that placement of a DDG in a high
permeability zone provided a blockage that diverted water into lower permeability areas,
thus increasing the sweep of target zones. Research results demonstrated that, although
higher recovery can be achieved with a polymer flood, the combination of delayed
production response and large polymer amounts cause such projects to be less
economically favorable than deep gel placement treatments. From results of several
sensitivity runs, it can be concluded that plug size and oil viscosity are two determining
factors in the efficiency of DDG treatments.
For the assumed case, economic analysis demonstrated that DDG has the most
positive net present value (NPV), with polymer flooding second and simply continuing
the waterflood to its economic limit the least positive NPV.
Advisors/Committee Members: Lane, Robert H. (advisor), Mamora, Daulat D. (committee member), Sun, Yuefeng (committee member).

► This thesis presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field scale surfactantpolymer…
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▼ This thesis presents a comprehensive simulation study on the impact of natural
fractures on the performance of surfactant polymer flood in a field scale surfactantpolymer
flood. The simulation model utilized for the study is a dual porosity dual
permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters
studied include wettability alteration, IFT changes and mobility reduction effect. The
results of this study clearly indicate the importance of reservoir description and fracture
modeling for a successful surfactant-polymer flood.
Naturally fractured carbonate reservoirs are usually characterized by mixed
wettablility and low matrix permeability which leads to low oil recovery and high
remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer
flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by
lowering the interfacial tension or altering the wettability. However, one of the main
reasons for failed surfactant-polymer floods is under-estimating the importance of the
reservoir especially the description of natural fractures and their effect on recovery.
Sensitivity runs were made to compare oil recovery capillary force, buoyancy force
and viscous force. The simulation study indicates that critical water saturation should be
reached before the start of surfactant-polymer flood to maximize oil recovery and utilize
the capillary force. Also, when a surfactant alters the rock wettability, an optimum IFT
should be identified for faster and higher imbibitions. The study shows that a contrast in
permeability between that of the fracture and that of the matrix will result in a slightly
lower oil recovery. Having the fracture perpendicular to the injector producer will result
in a higher areal sweep and lower residual oil.
A sensitivity study on the effect of the size of surfactant polymer slug was not
conclusive. Maximum adsorption capacity was reached which was one of the causes of
low imbibitions rate. Following the surfactant-polymer with water flood was able to
reverse the adsorption and restore some of the movable oil. The results show that if the
enhanced fluid that alter the wettability, imbibed in the matrix, injecting high IFT brine
will increase the rate of imbibition. The study calls for further investigation of this
phenomenon through research using a scaled laboratory model to verify the simulation
results.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Schechter, David S. (committee member), Gresham, Larry . G. (committee member).

► Water alternating gas (WAG) injection is a proven technique to enhance oil recovery. It has been successfully implemented in the field since 1957 with recovery…
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▼ Water alternating gas (WAG) injection is a proven technique to enhance oil
recovery. It has been successfully implemented in the field since 1957 with recovery
increase in the range of 5-10% of oil-initially-in-place (OIIP). In 2004, Herbert L. Stone
presented a simultaneous water and gas injection technique. Gas is injected near the
bottom of the reservoir and water is injected directly on top at high rates to prevent
upward channeling of the gas. Stone's mathematical model indicated the new technique
can increase vertical sweep efficiency by 3-4 folds over WAG. In this study, a
commercial reservoir simulator was used to predict the performance of Stone's
technique and compare it to WAG and other EOR injection strategies. Two sets of
relative permeability data were considered. Multiple combinations of total injection rates
(water plus gas) and water/gas ratios as well as injection schedules were investigated to
find the optimum design parameters for an 80 acre 5-spot pattern unit.
Results show that injecting water above gas may result in better oil recovery than
WAG injection though not as indicated by Stone. Increase in oil recovery with SSWAG
injection is a function of the gas critical saturation. The more gas is trapped in the formation, the higher oil recovery is obtained. This is probably due to the fact that areal
sweep efficiency is a more dominant factor in a 5-spot pattern. Periodic shut-off of the
water injector has little effect on oil recovery. Water/gas injection ratio optimization may
result in a slight increase in oil recovery. SSWAG injection results in a steady injection
pressure and less fluctuation in gas production rate compared to WAG injection.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Sun, Yuefeng (committee member), Schubert, Jerome J. (committee member).

► Pattern geometry plays a major role in determining oil recovery during waterflooding and enhanced oil recovery operations. Although simulation is an important tool for design…
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▼ Pattern geometry plays a major role in determining oil recovery during waterflooding
and enhanced oil recovery operations. Although simulation is an important tool for
design and evaluation, the first step often involves rough calculations based upon areal
sweep efficiencies of displacements in homogeneous, two-dimensional, scaled, physical
models. These results are available as a function of the displacement pattern and the
mobility ratio M.
In this research I studied the effect of mobility ratios on five-spot and staggered
waterflood patterns behavior for areal (2D) displacement in a reservoir that is
homogeneous and isotropic containing no initial gas saturation. Simulation was
performed using Eclipse 100 simulator.
Simulation results are presented as graphs of areal sweep efficiency at breakthrough
versus Craig mobility ratio for various staggered line drive aspect ratios.
The main results of the study are presented in the form of a graph of areal sweep
efficiency at breakthrough as a function of staggered line drive aspect ratio. This should
enable engineers to utilize the results in a convenient manner.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Ikelle, Luc T. (committee member), Schubert, Jerome J. (committee member).

► Production from a hydrocarbon reservoir is typically supported by water or carbon dioxide (CO2) injection. CO2 injection into hydrocarbon reservoirs is also a promising solution…
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▼ Production from a hydrocarbon reservoir is typically supported by water or carbon
dioxide (CO2) injection. CO2 injection into hydrocarbon reservoirs is also a promising
solution for reducing environmental hazards from the release of green house gases into
the earth?s atmosphere. Numerical simulators are used for designing and predicting the
complex behavior of systems under such scenarios. Two key steps in such studies are
forward modeling for performance prediction based on simulation studies using
reservoir models and inverse modeling for updating reservoir models using the data
collected from field.
The viability of time-lapse seismic monitoring using an integrated modeling of fluid
flow, including chemical reactions, and seismic response is examined. A
comprehensive simulation of the gas injection process accounting for the phase
behavior of CO2-reservoir fluids, the associated precipitation/dissolution reactions, and
the accompanying changes in porosity and permeability is performed. The simulation results are then used to model the changes in seismic response with time. The general
observation is that gas injection decreases bulk density and wave velocity of the host
rock system.
Another key topic covered in this work is the data assimilation study for hydrocarbon
reservoirs using Ensemble Kalman Filter (EnKF). Some critical issues related to EnKF
based history matching are explored, primarily for a large field with substantial
production history. A novel and efficient approach based on spectral clustering to select
?optimal? initial ensemble members is proposed. Also, well-specific black-oil or
compositional streamline trajectories are used for covariance localization. Approach is
applied to the Weyburn field, a large carbonate reservoir in Canada. The approach for
optimal member selection is found to be effective in reducing the ensemble size which
was critical for this large-scale field application. Streamline-based covariance
localization is shown to play a very important role by removing spurious covariances
between any well and far-off cell permeabilities.
Finally, time-lapse seismic study is done for the Weyburn field. Sensitivity of various
bulk seismic parameters viz velocity and impedance is calculated with respect to
different simulation parameters. Results show large correlation between porosity and
seismic parameters. Bulk seismic parameters are sensitive to net overburden pressure at
its low values. Time-lapse changes in pore-pressure lead to changes in bulk parameters
like velocity and impedance.
Advisors/Committee Members: Datta-Gupta, Akhil (advisor), Ehlig-Economides, Christine (committee member), Gibson, Richard L. (committee member), Mamora, Daulat D. (committee member).

► Steam Assisted Gravity Drainage (SAGD) is used widely as a thermal recovery technique in Canada to produce a very viscous bitumen formation. The main research…
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▼ Steam Assisted Gravity Drainage (SAGD) is used widely as a thermal recovery
technique in Canada to produce a very viscous bitumen formation. The main research
objectives of this simulation and experimental study are to investigate oil recovery
mechanisms under SAGD process with different injection fluids, including steam,
solvent or steam with solvent.
2D simulation studies based on typical Athabasca reservoir properties have
been performed. Results show that a successful solvent co-injection design can utilize
the advantages of solvent and steam. There is an optimal solvent type and
concentration ratio range for a particular reservoir and operating condition. Long,
continuous shale barriers located vertically above or near the wellbore delay
production performance significantly. Co-injecting a multi-component solvent can
flush out the oil in different areas with different drainage mechanisms from vaporized
and liquid components. Placing an additional injector at the top of the reservoir results
only in marginal improvement. The pure high-temperature diluent injection appears
feasible, although further technical and economic evaluation of the process is required.
A 2D scaled physical model was fabricated that represented in cross-section a
half symmetry element of a typical SAGD drainage volume in Athabasca. The
experimental results show co-injecting a solvent mixture of C7 and xylene with steam
gives better production performance than the injection of pure steam or steam with C7
at the study condition. Compared to pure steam injection runs ( Run 0 and 1),
coinjecting C7 (Run 2) with steam increases the ultimate recovery factor of oil inside
the cell from 25 percent to 29 percent and decreases the ultimate CSOR from 2.2 to 1.9 and the
ultimate CEOR from 4892 J/cm
3
to 4326 J/cm
3
; coinjecting C7 and Xylene (Run 3)
increases the ultimate recovery factor of oil from 25 percent to 34 percent, and decreases the
ultimate CSOR 2.2 to 1.6 and the ultimate CEOR from 4892 J/cm
3
to 3629 J/cm
3
.
Analyses of the experimental results indicate that partial pressure and the near
wellbore flow play important roles in production performance.
In conclusion, a successful solvent injection design can effectively improve the
production performance of SAGD. Further research on evaluating the performance of
various hydrocarbon types as steam additives is desirable and recommended.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Ayers, Walter B. (committee member), Schubert, Jerome J. (committee member), Sun, Yuefeng (committee member).

► Integrated reservoir modeling has become an important part of day-to-day decision analysis in oil and gas management practices. A very attractive and promising technology is…
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▼ Integrated reservoir modeling has become an important part of day-to-day
decision analysis in oil and gas management practices. A very attractive and promising
technology is the use of time-lapse or 4D seismic as an essential component in subsurface
modeling. Today, 4D seismic is enabling oil companies to optimize production and
increase recovery through monitoring fluid movements throughout the reservoir. 4D
seismic advances are also being driven by an increased need by the petroleum
engineering community to become more quantitative and accurate in our ability to
monitor reservoir processes. Qualitative interpretations of time-lapse anomalies are being
replaced by quantitative inversions of 4D seismic data to produce accurate maps of fluid
saturations, pore pressure, temperature, among others.
Within all steps involved in this subsurface modeling process, the most
demanding one is integrating the geologic model with dynamic field data, including 4Dseismic
when available. The validation of the geologic model with observed dynamic
data is accomplished through a "history matching" (HM) process typically carried out
with well-based measurements. Due to low resolution of production data, the validation
process is severely limited in its reservoir areal coverage, compromising the quality of the
model and any subsequent predictive exercise. This research will aim to provide a novel
history matching approach that can use information from high-resolution seismic data to
supplement the areally sparse production data. The proposed approach will utilize
streamline-derived sensitivities as means of relating the forward model performance with
the prior geologic model. The essential ideas underlying this approach are similar to those
used for high-frequency approximations in seismic wave propagation. In both cases, this leads to solutions that are defined along "streamlines" (fluid flow), or "rays" (seismic
wave propagation). Synthetic and field data examples will be used extensively to
demonstrate the value and contribution of this work.
Our results show that the problem of non-uniqueness in this complex history
matching problem is greatly reduced when constraints in the form of saturation maps
from spatially closely sampled seismic data are included. Further on, our methodology
can be used to quickly identify discrepancies between static and dynamic modeling.
Reducing this gap will ensure robust and reliable models leading to accurate predictions
and ultimately an optimum hydrocarbon extraction.
Advisors/Committee Members: Datta-Gupta, Akhill (advisor), Lee, W. John (committee member), Mamora, Daulat (committee member), Efendiev, Yalchin (committee member).

► Waterflood optimization via rate control is receiving increased interest because of rapid developments in the smart well completions and I-field technology. The use of inflow…
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▼ Waterflood optimization via rate control is receiving increased interest because
of rapid developments in the smart well completions and I-field technology. The use of
inflow control valves (ICV) allows us to optimize the production/injection rates of
various segments along the wellbore, thereby maximizing sweep efficiency and delaying
water breakthrough. It is well recognized that field scale rate optimization problems are
difficult because they often involve highly complex reservoir models, production and
facilities related constraints and a large number of unknowns. Some aspects of the
optimization problem have been studied before using mainly optimal control theory.
However, the applications to-date have been limited to rather small problems because of
the computation time and the complexities associated with the formulation and solution
of adjoint equations. Field-scale rate optimization for maximizing waterflood sweep
efficiency under realistic field conditions has still remained largely unexplored.
We propose a practical and efficient approach for computing optimal injection
and production rates and thereby manage the waterflood front to maximize sweep
efficiency and delay the arrival time to minimize water cycling. Our work relies on
equalizing the arrival times of the waterfront at all producers within selected sub-regions
of a water flood project. The arrival time optimization has favorable quasi-linear
properties and the optimization proceeds smoothly even if our initial conditions are far
from the solution. We account for geologic uncertainty using two optimization schemes.
The first one is to formulate the objective function in a stochastic form which relies on a
combination of expected value and standard deviation combined with a risk attitude coefficient. The second one is to minimize the worst case scenario using a min-max
problem formulation. The optimization is performed under operational and facility
constraints using a sequential quadratic programming approach. A major advantage of
our approach is the analytical computation of the gradient and Hessian of the objective
which makes it computationally efficient and suitable for large field cases.
Multiple examples are presented to support the robustness and efficiency of the
proposed optimization scheme. These include several 2D synthetic examples for
validation purposes and 3D field applications.
Advisors/Committee Members: Datta Gupta, Akhil (advisor), Hill, A. Daniel (committee member), Mamora, Daulat D. (committee member), Bangerth, Wolfgang (committee member).

► In assessing the economic viability of a waterflood project, a key parameter is the remaining oil saturation (ROS) within each pattern unit. This information helps…
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▼ In assessing the economic viability of a waterflood project, a key parameter is the
remaining oil saturation (ROS) within each pattern unit. This information helps in
identifying the areas with the highest ROS and thus potential for further development.
While special core analysis, log-inject-log, and thermal-decay time-log-evaluation
techniques are available, they provide only single-point values and a snapshot in time
near a wellbore. Also, they can quickly add up to an expensive program.
The analytical areal distribution method estimates ROS in a waterflood pattern unit from
material balance calculations using well injection and production data with no pressure
information required. Well production and injection volumes are routinely measured in
oilfield operations, making the method very attractive.
The areal distribution technique estimates two major uncertainties: vertical loss of
injected water into nontarget areas or areal loss into surrounding patterns, and injected
water for gas fill-up. However, developers tested it only in low-pressure conditions,
which are increasingly rare in oilfield operations. The main purpose of my research, then, was to verify whether or not the areal
distribution method is valid in higher pressure conditions. Simulation of various
waterflood patterns confirmed that the areal distribution method with its estimated ROS
is capable of precise estimation of actual ROS, but at high pressures it requires
consideration of pressure data in addition to injection and production data.
Advisors/Committee Members: Barrufet, Maria (advisor), Mamora, Daulat (advisor), Schubert, Jerome (committee member).

▼ Although carbonates hold more than 60 percent of the world's oil reserves, they, nevertheless, exhibit much lower average recovery factor values than terrigenous
sandstone reservoirs. Thus, utilization of advanced enhanced oil recovery (EOR) techniques such as high pressure CO2 injection may normally be required to recover oil in place in carbonate reservoirs. This study addresses how different rock types can influence the seismic monitoring of CO2 sequestration in carbonates.
This research utilizes an elastic parameter, defined in a rock physics model of poroelasticity and so-?called as the frame flexibility factor, to successfully quantify the carbonate pore types in core samples available from the Great Bahama Bank (GBB). This study shows that for carbonate samples of a given porosity the lower the frame flexibility factors the higher is the sonic wave velocity. Generally, samples with frame flexibility values of <4 are either rocks with visible moldic pores or intraframe porosity; whereas, samples with frame flexibility values of >4 are rocks with intercrystalline and microporosity. Hence, different carbonate pore geometries can be quantitatively predicted using the elastic parameters capable of characterizing the porous media with a representation of their internal structure on the basis of the flexibility of the frame and pore connectivity.
In this research, different fluid substitution scenarios of liquid and gaseous CO2 saturations are demonstrated to characterize the variations in velocity for carbonate-specific pore types. The results suggest that the elastic response of CO2 flooded rocks is mostly governed by pore pressure conditions and carbonate rock types. Ultrasonic P-?wave velocities in the liquid-?phase CO2 flooded samples show a marked decrease in the order of 0.6 to 16 percent. On the contrary, samples flooded with gaseous-?phase CO2 constitute an increase in P-?wave velocities for moldic and intraframe porosities, while establishing a significant decrease for samples with intercrystalline and micro-?porosities. Such velocity variations are explained by the stronger effect of density versus
compressibility, accounting for the profound effect of pore geometries on the acoustic properties in carbonates.
The theoretical results from this research could be a useful guide for interpreting the response of time-?lapse seismic monitoring of carbonate formations following CO2
injection at depth. In particular, an effective rock-?physics model can aid in better discrimination of the profound effects of different pore geometries on seismic monitoring of CO2 sequestration in carbonates.
Advisors/Committee Members: Sun, Yuefeng F. (advisor), Ahr, Wayne (committee member), Mamora, Daulat D. (committee member).

▼ Seismic data processing depends on mathematical and statistical tools such as
convolution, crosscorrelation and stack that employ second-order statistics (SOS).
Seismic signals are non-Gaussian and therefore contain information beyond SOS. One of
the modern challenges of seismic data processing is reformulating algorithms e.g.
migration, to utilize the extra higher order statistics (HOS) information in seismic data.
The migration algorithm has two key components: the moveout correction, which
corresponds to the crosscorrelation of the migration operator with the data at zero lag
and the stack of the moveout-corrected data. This study reformulated the standard
migration algorithm to handle the HOS information by improving the stack component,
having assumed that the moveout correction is accurate. The reformulated migration
algorithm outputs not only the standard form of stack, but also the variance, skewness
and kurtosis of moveout-corrected data.
The mean (stack) of the moveout-corrected data in this new concept is equivalent
to the migration currently performed in industry. The variance of moveout-corrected
data is one of the new outputs obtained from the reformulation. Though it characterizes
SOS information, it is not one of the outputs of standard migration. In cases where the
seismic amplitude variation with offset (AVO) response is linear, a single algorithm that outputs mean (stack) and variance combines both the standard AVO analysis and
migration, thereby significantly improving the cost of seismic data processing.
Furthermore, this single algorithm improves the resolution of seismic imaging, since it
does not require an explicit knowledge of reflection angles to retrieve AVO information.
In the reformulation, HOS information is captured by the skewness and kurtosis
of moveout-corrected data. These two outputs characterize nonlinear AVO response and
non-Gaussian noise (symmetric and nonsymmetric) that may be contained in the data.
Skewness characterizes nonsymmetric, non-Gaussian noise, whereas kurtosis
characterizes symmetric, non-Gaussian noise. These outputs also characterize any errors
associated with moveout corrections.
While classical seismic data processing provides a single output, HOS-related
processing outputs three extra parameters i.e. the variance, skewness, and kurtosis.
These parameters can better characterize geological formations and improve the
accuracy of the seismic data processing performed before the application of the
reformulated migration algorithm.
Advisors/Committee Members: Ikelle, Luc T. (advisor), Hopper, John R. (committee member), Mamora, Daulat D. (committee member).

► Conventionally streamlines are traced using total flux across the grid cell faces. The visualization of total flux streamlines shows the movement of flood, injector-producer relationship,…
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▼ Conventionally streamlines are traced using total flux across the grid cell faces. The
visualization of total flux streamlines shows the movement of flood, injector-producer
relationship, swept area and movement of tracer. But they fail to capture some important
signatures of reservoir dynamics, such as dominant phase in flow, appearance and
disappearance of phases (e.g. gas), and flow of components like CO2.
In the work being presented, we demonstrate the benefits of visualizing phase and
component streamlines which are traced using phase and component fluxes respectively.
Although the phase and component streamlines are not appropriate for simulation, as they
might be discontinuous, they definitely have a lot of useful information about the
reservoir processes and recovery mechanisms.
In this research, phase and component streamline tracing has been successfully
implemented in three-phase and compositional simulation and the additional information
obtained using these streamlines have been explored. The power and utility of the phase
and component streamlines have been demonstrated using synthetic examples and two
field cases. The new formulation of streamline tracing provides additional information
about the reservoir drive mechanisms. The phase streamlines capture the dominant phase in flow in different parts of the reservoir and the area swept corresponding to different
phases can be identified. Based on these streamlines the appearance and disappearance of
phases can be identified. Also these streamlines can be used for optimizing the field
recovery processes like water injection and location of infill wells. Using component
streamlines the movement of components like CO2 can be traced, so they can be used for
optimizing tertiary recovery mechanisms and tracking of tracers. They can also be used to
trace CO2 in CO2 sequestration project where the CO2 injection is for long term storage in
aquifers or reservoirs. They have also other potential uses towards study of reservoir
processes and behavior such as drainage area mapping for different phases, phase rate
allocations to reservoir layers, etc.
Advisors/Committee Members: Datta-Gupta, Akhil (advisor), Efendiev, Yalchin (committee member), Mamora, Daulat D. (committee member).

► Experimental studies showed the feasibility of adding metallic catalysts and tetralin for the upgrade and increased recovery of heavy oil during the in situ combustion…
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▼ Experimental studies showed the feasibility of adding metallic catalysts and
tetralin for the upgrade and increased recovery of heavy oil during the in situ combustion
process. Further experimental studies also showed the applicability of in situ combustion
as a viable method of upgrading and improving recovery of intermediate oils.
Three successful experimental runs were performed with heavy oil from Mexico
(10.1 degrees API gravity). The first run was the control run without the addition of tetralin or
metallic catalysts; the second run used heavy oil premixed with 3 wt% tetralin and
500ppm nickel catalyst; and the third run was with heavy oil premixed with 3 wt%
tetralin and 500ppm iron catalyst. For the three runs, the cell production pressure was
kept constant at 300 psig. The combustion cell was placed in a vacuum jacket and set to
a temperature of 60 degrees C. For the only successful run with the intermediate Texas oil
(22.0 degrees API gravity), the production pressure was also kept constant at 300 psig but the
vacuum jacket temperature was set to a reservoir temperature of 40 °C. During the runs
for both oils, samples of produced oils and combustion flue gases were collected at regular intervals for analysis. These analyses included determination of oil viscosity and
density, oil recovery, combustion front velocity, and apparent H/C ratio.
Experimental results for the intermediate oil run, the oil gravity increased by 6
points showing the upgrading effects of in situ combustion on intermediate oils. Also,
the high average combustion temperatures observed during the run indicated that in situ
combustion may be applicable to reservoirs of similar characteristics to the intermediate
Texas oil reservoir.
Heavy oil experimental run results indicated that the use of tetralin and metallic
catalysts increase the average combustion front temperature from 484 degrees C to 501 degrees C for the
run with nickel catalysts, and from 484 degrees C to 492 degrees C for the run with iron catalysts. These
results also show an increase in produced oil recovery from 83% to 90% of oil initially
in place for the nickel catalyst run, and 83% to 86% of oil initially in place for the iron
catalyst run.
Advisors/Committee Members: Mamora, Daulat D. (advisor), Schubert, Jerome (committee member), Sun, Yuefung (committee member).

► Steam injection with added surface active chemicals is one of general EOR processes aimed to recover residual oil after primary production processes. It has been…
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▼ Steam injection with added surface active chemicals is one of general EOR
processes aimed to recover residual oil after primary production processes. It has been
demonstrated that, after waterflooding, an oil swept area can be increased by steam
surfactant flow due to the reduced steam override effect as well as reduced interfacial
tension between oil and water in the formation. To investigate the ability to improve
recovery of 20.5oAPI California heavy oil with steam surfactant injection, several
experiments with a one-dimensional model were performed.
Two experimental models with similar porous media, fluids, chemicals, as well
as injection and production conditions, were applied. The first series of experiments
were carried out in a vertical cylindrical injection cell with dimensions of 7.4 cm x 67
cm. The second part of experiment was conducted using a horizontal tube model with
dimensions of 3.5 cm x 110.5 cm. The horizontal model with a smaller diameter than the
vertical injection cell is less subject to channel formation and is therefore more applicable for the laboratory scale modeling of the one-dimensional steam injection
process.
Nonionic surfactant Triton X-100 was coinjected into the steam flow. For both
series of experimental work with vertical and horizontal injection cells, the concentration
of Triton X-100 surfactant solution used was chosen 3.0 wt%. The injection rates were
set to inject the same 0.8 pore volumes of steam for the vertical model and 1.8 pore
volumes of steam for horizontal model.
The steam was injected at superheated conditions of 200 °C and pressure of 100
psig. The liquid produced from the separator was sampled periodically and treated to
determine oilcut and produced oil properties. The interfacial tension (IFT) of the
produced oil and water were measured with an IFT meter and compared to that for the
original oil. The experimental study demonstrated that the average incremental oil
recovery with steam surfactant flood is 7 % of the original oil-in-place above that with
pure steam injection.
Advisors/Committee Members: Mamora, Daulat (advisor), Sun, Yuefeng (committee member), Ayers, Walter (committee member).

► A global steady increase of energy consumption coupled with the decline of conventional oil resources points to a more aggressive exploitation of heavy oil. Heavy…
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▼ A global steady increase of energy consumption coupled with the decline of conventional oil resources points to a more aggressive exploitation of heavy oil. Heavy oil is a major source of energy in this century with a worldwide base reserve exceeding 2.5 trillion barrels. Management decisions and production strategies from thermal oil recovery processes are frequently based on reservoir simulation. A proper description of the physical properties, particularly oil viscosity, is essential in performing reliable modeling studies of fluid flow in the reservoir. We simulated cyclic steam injections on the highly viscous Hamaca oil, with a viscosity of over 10,000 cp at ambient temperature, and the production was drastically impacted by up to an order of magnitude when using improper mixing rules to describe the oil viscosity. This thesis demonstrates the importance of these mixing rules and alerts reservoir engineers to the significance of using different options simulators have built in their platforms to describe the viscosity of heavy oils. Log linear and power mixing rules do not provide enough flexibility to describe the viscosity of extra heavy oil with temperature. A recently implemented mixing rule in a commercial simulator has been studied providing satisfactory results. However, the methodology requires substantial interventions, and cannot be automatically updated. We provide guidelines to improve it and suggest more flexible mixing rules that could easily be implemented in commercial simulators. We also provide a methodology to determine the adequate time for each one of the periods in cyclic steam injection: injection, soaking and production. There is a lot of speculation in this matter and one of the objectives of this thesis is to better understand and provide guidelines to optimize oil production using proper lengths in each one of these periods. We have found that the production and injection periods should be similar in time length. Nevertheless, the production period should not be less than the injection period. On the other hand, the soaking period should be as short as possible because it is unproductive time in terms of field oil production for the well and therefore it translates into a negative cash flow for a company.
Advisors/Committee Members: Barrufet, Maria (advisor), Ikelle, Luc (committee member), Mamora, Daulat (committee member).

► The Pliocene-Recent Muda formation is essentially undeformed in the West Natuna Basin, and excellent resolution of this interval on three-dimensional seismic data in Belida Field…
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▼ The Pliocene-Recent Muda formation is essentially undeformed in the West
Natuna Basin, and excellent resolution of this interval on three-dimensional seismic data
in Belida Field allows detailed interpretation of component fluvial-deltaic systems.
Detailed interpretation of seismic time slice and seismic sections along with seismic
facies analysis, horizon mapping, and extraction of seismic attributes provide the basis to
construct a sequence stratigraphic framework and determine patterns for sediment
dispersal and accumulation.
The Muda interval contains five third-order sequences, with depositional
environments confined to the shelf and consisting mainly of fluvial elements. Sequence
boundaries (SB) apparently result from major sea level falls, since there was no tectonic
uplift and the field underwent only regional slow subsidence during sedimentation of the
study interval.
Sea level fluctuation also caused changes in fluvial patterns. Analysis of
changing channel patterns indicates that major systems tracts relate to specific channel
patterns. The Lowstand Systems Tract (LST) is generally dominated by larger channel dimensions and low sinuosity channel patterns. The Transgressive Systems Tract (TST)
typically contains relatively smaller channels with high sinuosity. Channels in the
Highstand Systems Tract (HST) generally show moderate sinuosity channels and are
intermediate in size, larger than TST channels but smaller than LST channels. Crossplots
of stratigraphic position and channel morphology indicate that within the transition from
LST-TST, channel dimensions (width and thickness) generally decrease and channel
sinuosity generally increases.
High sinuosity, meandering and anastomosing channels are generally found near
the maximum flooding surface. Low sinuosity channels occur within the HST-SB-LST
succession, with the exception of higher sinuosity meandering channels evolving inside
valleys. Larger, lower sinuosity channels result from high gradient and high discharge
associated with stream piracy. Smaller, high-sinuosity channels result from low gradient
and small discharge.
Extraction of seismic attributes such as RMS Amplitude and Average Reflection
Strength show these depositional features in greater detail. In the Belida Field area,
lowstand channels were found to comprise the greatest volume of sandstone bodies.
Seismic delineation of the distribution and morphology of these channel systems provides
critical input for reservoir modeling and volumetric analysis.
Advisors/Committee Members: Dorobek, Steven L. (advisor), Mamora, Daulat D. (committee member), Willis, Brian J. (committee member).

► An experimental study has been conducted to compare the effect of steam injection and caustic steam injection in improving the recovery of San Ardo and…
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▼ An experimental study has been conducted to compare the effect of steam injection and caustic steam injection in improving the recovery of San Ardo and Duri heavy oils. A 67 cm long x 7.4 cm O.D (outer diameter), steel injection cell is used in the study. Six thermocouples are placed at specific distances in the injection cell to record temperature profiles and thus the steam front velocity. The injection cell is filled with a mixture of oil, water and sand. Steam is injected at superheated conditions of 238 °C with the cell outlet pressure set at 200 psig, the cell pressure similar to that found in San Ardo field. The pressure in the separators is kept at 50 psig. The separator liquid is sampled at regular intervals. The liquid is centrifuged to determine the oil and water volumes, and oil viscosity, density and recovery. Acid number measurements are made by the titration method using a pH meter and measuring the EMF values. The interfacial tensions of the oil for different concentrations of NaOH are also measured using a tensionometer.
Experimental results show that for Duri oil, the addition of caustic results in an increase in recovery of oil from 52% (steam injection) to 59 % (caustic steam injection). However, caustic has little effect on San Ardo oil where oil recovery is 75% (steam injection) and 76 % (caustic steam injection). Oil production acceleration is seen with steam-caustic injection. With steam caustic injection there is also a decrease in the produced oil viscosity and density for both oils. Sodium hydroxide concentration of 1 wt % is observed to give the lowest oil-caustic interfacial tension. The acid numbers for San Ardo and Duri oil are measured as 6.2 and 3.57 respectively.
Advisors/Committee Members: Mamora, Daulat (advisor), Sunik, Zoran (committee member), Schubert, Jerome (committee member).

► Nowadays, field development strategy has become increasingly dependent on the results of reservoir simulation models. Reservoir studies demand fast and efficient results to make investment…
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▼ Nowadays, field development strategy has become increasingly dependent on the
results of reservoir simulation models. Reservoir studies demand fast and efficient results
to make investment decisions that require a reasonable trade off between accuracy and
simulation time. One of the suitable options to fulfill this requirement is streamline
reservoir simulation technology, which has become very popular in the last few years.
Streamline (SL) simulation provides an attractive alternative to conventional reservoir
simulation because SL offers high computational efficiency and minimizes numerical
diffusion and grid orientation effects. However, streamline methods have weaknesses
incorporating complex physical processes and can also suffer numerical accuracy
problems.
The main objective of this research is to evaluate the numerical accuracy of the
latest SL technology, and examine the influence of different factors that may impact the
solution of SL simulation models. An extensive number of numerical experiments based
on sensitivity analysis were performed to determine the effects of various influential
elements on the stability and results of the solution. Those experiments were applied to
various models to identify the impact of factors such as mobility ratios, mapping of
saturation methods, number of streamlines, time step sizes, and gravity effects. This study
provides a detailed investigation of some fundamental issues that are currently
unresolved in streamline simulation.
Advisors/Committee Members: Datta-Gupta, Akhil (advisor), Mamora, Daulat (committee member), Gibson, Richard (committee member).

► This dissertation solves an optimization problem in the area of scheduling large-scale petroleum development projects under several resources constraints. The dissertation focuses on the application…
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▼ This dissertation solves an optimization problem in the area of scheduling large-scale
petroleum development projects under several resources constraints. The dissertation
focuses on the application of a metaheuristic search Genetic Algorithm (GA) in solving
the problem. The GA is a global search method inspired by natural evolution. The
method is widely applied to solve complex and sizable problems that are difficult to
solve using exact optimization methods. A classical resource allocation problem in
operations research known under Knapsack Problems (KP) is considered for the
formulation of the problem.
Motivation of the present work was initiated by certain petroleum development
scheduling problem in which large-scale investment projects are to be selected subject to
a number of resources constraints in several periods. The constraints may occur from
limitations in various resources such as capital budgets, operating budgets, and drilling
rigs. The model also accounts for a number of assumptions and business rules encountered in the application that motivated this work. The model uses an economic
performance objective to maximize the sum of Net Present Value (NPV) of selected
projects over a planning horizon subject to constraints involving discrete time dependent
variables.
Computational experiments of 30 projects illustrate the performance of the model.
The application example is only illustrative of the model and does not reveal real data. A
Greedy algorithm was first utilized to construct an initial estimate of the objective
function. GA was implemented to improve the solution and investigate resources
constraints and their effect on the assets value.
The timing and order of investment decisions under constraints have the prominent
effect on the economic performance of the assets. The application of an integrated
optimization model provides means to maximize the financial value of the assets,
efficiently allocate limited resources and to analyze more scheduling alternatives in less
time.
Advisors/Committee Members: Startzman, Richard A. (advisor), El-Halwagi, Mahmoud (committee member), Mamora, Daulat D. (committee member), Wattenbarger, Robert A. (committee member).